The high cost of upgrading 40-year-old nuclear reactors is confronting Xcel Energy again.

Investments in the Prairie Island nuclear power plant in Red Wing, Minn., are projected to cost more than expected — $487 million by 2020, with more spending needed in the next decade.

It’s not a replay of cost overruns at Xcel’s other reactor in Monticello, Minn. That 2013 surprise, which state regulators blamed on imprudent management, led Xcel to write off $125 million last year.

This time, Xcel executives are giving advance warning of rising costs to upgrade its two Prairie Island reactors. The investment will keep the units running safely until the early 2030s, Xcel officials said, and will largely be offset by lower maintenance expenses in years ahead.

“We learned from what happened at Monticello,” Kevin Davison, Xcel’s site vice president at Prairie Island, said in an interview at the plant. “ … We have got to be better at making sure we totally understand what we want to do, exactly how we are going to do it and be very careful in the cost considerations.”

Yet, in a fresh surprise, Xcel also has offered to study shutting down Prairie Island years before the reactors’ operating licenses expire in 2033-34. Xcel isn’t pushing early retirement, which would accelerate the costly job of decommissioning. It’s an option being presented to the Minnesota Public Utilities Commission, which regulates Xcel’s rates and investments.

Raymond Grumney

Graphic: The state of U.S. nuclear plants

Two nuclear plants, including one in Wisconsin, have shut down for economic reasons since 2013. Four other nuclear plants in other states face similar challenges and are slated to close by 2019.

Even if Xcel retires its Prairie Island units in the 2020s, the Minneapolis-based utility said significant investment is needed just to keep them operating for a few years. One of the plant’s two generators is the original unit, and is to be replaced in 2018 if not sooner. Four cooling towers also need refurbishment or replacement, as do dozens of decades-old pumps, motors and controls, the utility said.

The projected cost of those and other upgrades has risen $175 million from earlier estimates, for a total of $487 million, including financing allowances. The sticker shock isn’t as bad as it was at Monticello, where the price had more than doubled to $748 million over five years.

But the near-term investment in the Prairie Island plant isn’t the end of the story. Xcel said another $600 million to $900 million in additional work likely will be needed at Prairie Island in the 2020s.

Although Xcel also is planning significant new investments in wind and solar power, Laura McCarten, a regional vice president for Xcel, said that carbon-free energy from nuclear power is no less important. “It really is a cornerstone, a pillar of Xcel Energy moving forward to get to 60 percent carbon-free energy by 2030,” she said.

Xcel, the state’s largest power company with 1.2 million customers, isn’t the only U.S. utility struggling with nuclear economics. But its nuclear plants differ from five recently retired or soon-to-be-shuttered nuclear power plants whose owners have declared them economically challenged.

All of those plants are “merchant” power generators. Their owners don’t serve retail customers like Xcel. Instead, they sell wholesale electricity into competitive power markets established in some states, like Illinois. Minnesota has a more traditional power market.

“It’s the merchant nuclear plants that are falling by the wayside,” said Arnie Gundersen, a nuclear engineer with Fairewinds Energy Education, a Vermont-based nonprofit consulting group.

Gundersen said merchant plants are struggling to compete against power generated by low-priced natural gas, wind and even solar. By contrast, Xcel nuclear costs get added to customers’ rates if regulators determine they are prudent. Minnesota regulators also consider carbon emissions in long-range planning for utility investments — a process now underway at Xcel.

“If they had to compete in the power market right now, they might be in the same situation,” said Gundersen, whose group advised Vermont on the 2013 shutdown of the Vermont Yankee nuclear plant.

In Minnesota, interest groups like the Prairie Island Indian Community, whose homes and businesses are closest to the Prairie Island nuclear plant, have not yet weighed in on whether Xcel should study early retirement. Nor has the state Commerce Department, which is analyzing Xcel’s pending request for a 9.8 percent rate hike. The department has asked Xcel for more information about possible retirement.

“The time is right to have that discussion,” said Davison, the plant’s site vice president. “It is a complicated question … that really does require a very thoughtful, sophisticated analysis.”

Closing the plant, and the loss of up to 800 good-paying jobs, would hurt the Red Wing region. Mayor Daniel Bender said the plant is the city’s largest taxpayer, and its workers are an important part of the community. He said Xcel has scheduled a meeting with city officials to discuss its plans.

“We’ve had some internal discussions about what it would mean, but it is difficult to say,” said Bender.

$1.9B invested since 2008

Xcel Energy has invested $1.9 billion in its two nuclear power plants since 2008, and that doesn’t include the cost of periodic refuelings.

GLEN STUBBE, Star Tribune

Xcel Energy’s Prairie Island nuclear plant in Red Wing has been operating for four decades and is licensed to run until 2033-34. Xcel recently offered to study shutting down the plant before then, though it isn’t pushing that option.

Many systems in the older, single-unit Monticello plant have been replaced, and its power output increased. Prairie Island also has undergone a series of upgrades, including a new steam generator in 2013 and a power generator in 2015. Both plants also have made safety upgrades, including changes based on lessons from Japan’s Fukushima Daiichi disaster in 2011, when a tsunami damaged three reactors.

All of it is premised on Xcel’s plan to keep its nuclear reactors operating until their extended, 60-year licenses expire in the 2030s. Xcel and other nuclear industry officials also have talked about whether another license extension, to 80 years, is possible.

Davison said some of the recent and near-term upgrades address safety issues such as the risk of in-plant fires. Post-Fukushima investments weren’t envisioned in 2008, when Xcel laid out a long-term investment plan to regulators. Other upgrades are practical steps to replace old equipment that requires high maintenance.

Although the Prairie Island plant has a solid performance record — one unit ran more than 600 days straight before being shut down for refueling in 2014 — its recent history is spotty. The units had six forced shutdowns in 2015, including some that drew heightened scrutiny from the U.S. Nuclear Regulatory Commission. Xcel says replacing old equipment will help reduce such shutdowns, which can last for days or weeks while repairs are made.

“We will see it in higher reliability for both units,” Davison said. “They will be online producing megawatts more often — 95 percent of the time — and we will see it with lower outage costs going forward. We think it is a good value proposition that meets our goals for carbon reduction.”

Yet sometimes new equipment brings headaches. That happened at Prairie Island Unit 2 in December. Just 11 days after a new $68 million generator was installed, it failed, forcing a shutdown that lasted two months. With the unit still under warranty, manufacturer Mitsubishi sent 52 technicians to figure out what happened, Davison said. It turned out that a small piece of metal had been left inside the unit; it had worn away some insulation, causing a ground fault, he added. The repaired unit went back on line in February.

Dave Lochbaum, a nuclear safety expert for the Union of Concerned Scientists, said new equipment can mean new problems, though plants usually correct them as Xcel and Mitsubishi did. In the worst such fiasco, the San Onofre nuclear plant in California was shuttered in 2013 after a new steam generator failed.

“That’s the wild card,” said Lochbaum. “You can have a list of things you want to replace, and your cost estimates are based on the fixes being an improvement. Nobody can anticipate those kinds of problems and I don’t envy the people making those calls.”

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